Eliminating formation damage, reducing rig time
Novel completion technology in sand control applications
Garry Garfield and Paul McElfresh; Baker Oil Tools
Baker Oil Tools developed a new technology for completing wells in unconsolidated formations. The technology and technique is installing a liner hanger and sand control mechanism in a single trip to eliminate explosive perforation charges and associated formation damage risk. The BOT personnel can run production liner, flow conduit, primary cementing, and sand control tools in a single trip resulting in cost reduction. A Joint Investment Project (JIP) that included three major operators, a large service provider, and a small technology company, with the help of a grant from the Department of Energy, developed this new technology.
Formation damage caused by perforating is one of the highest risks in well completions. Common types of damage that can occur inside the perforation tunnel are fractured and compacted zones, perforation gun debris, and broken formation blockages. Reducing or eliminating initial perforation damage results in a more productive well over its lifetime.
BOT’s new completion method eliminates gravel packing and minimizes intervention in completion operations, saving substantial rig time. It also simplifies operation logistics, especially in remote or offshore environments.
Open flow area
Generally, the greater the area open to flow through a perforation tunnel, the greater the productivity of the well. A larger entry hole diameter can allow an increase in the area open to flow. Conversely, a decrease in flow area can restrict the amount of flow through a perforation tunnel. A lower shot density can result in a decrease in total flow area for production. Increasing the shot density equates to a larger effective flow area, and perforation tunnels must be open to be filled with gravel pack sand to prevent filling with formation sand. If the formation sand fills the perforation tunnel, the pressure drop in the perforation is extreme and will affect the well productivity.
The most difficult type of formation damage to remove is the near-wellbore damage, which was affected by the drilling and completion fluid. Deep penetrating perforating charges can bypass drilling and completion fluid formation damage. However, deep penetrating charges yield a smaller casing entrance hole diameter; hence making it more difficult to place gravel pack sand. If the perforation tunnel is not filled with gravel pack sand, the result is high perforation flow velocities and formation sand production, which could damage screens.
Perforation damage
The effect of perforation damage, the crushed zone caused by perforating, can restrict flow from the formation into the perforation. This flow restriction from the formation significantly can decrease well productivity and increase the overall skin of the well. Perforation debris causes decreases in well productivity simply because the debris in the perforation tunnel blocks the available flow area.
The history of formation damage caused by perforating is well documented. Studies have shown that conventional perforating of cased wells can cause an increase in skin values, especially over the extended lifetime of the well. Studies have shown that deep penetrating charges create less of a damaged zone when compared to big hole charges. However, restricting the penetration of the big hole charge can minimize this damage.
Eliminating perforating debris
Reducing or eliminating initial formation damage resulted in a more productive well over its lifetime. The JIP developed a technology system that could not only reduce or eliminate formation damage, but also reduce rig time and increase overall cost savings in wellbore completions. Each JIP member brought expertise from their own field of experience to develop the system that would revolutionize sand control completion methodology.
The JIP used a number of design criteria to satisfy the new system. It had to control sand production, limit or remove formation damage caused by conventional perforating and drilling fluids, and reduce rig time to save on overall completion costs.
Telescoping conduit
The JIP developed a one-trip sand completion system that included telescoping flow conduit technology and performed the following functions in a single trip:
- Installed and deployed a standard liner hanger system
- Commenced primary cementing operations
- Provided a production conduit
- Provided sand control.
The system minimizes rig time by combining multiple operations into a single trip without jeopardizing simplicity or reliability. By eliminating the need for perforating, the system also eliminates the associated formation damage and debris removal.
The heart of the system is a telescoping conduit that connects the reservoir face to the production liner. After the completion system attaches to the liner string at surface and runs in the hole, the conduits align with the producing zone (in a method similar to that for a perforating gun). Then each flow conduit device extends using hydraulic pressure to form a seal on the formation face. There is no type of explosive charge that could damage the formation face. The seal of the telescoping mechanism penetrates the drill-in fluid filter cake. There are two extension lengths: a gauge-hole extension and a wash-out extension. The gauge-hole extension length seals on the face of an open hole that the rig hands drilled to gauge with a drill-ing fluid. If the rig hands encounter a wash out, the conduit device extends further to seal on the formation to ensure full contact with the reservoir.
During the manufacturing process, BOT personnel fill each conduit tube with sand control media. The filtration media uses stainless steel beads in combination with a sintering process for strength, durability, and erosion resistance. The sintering process strengthens the beads while leaving pore throat openings comparable to gravel pack sands. Depending on individual well characteristics based on core samples and sieve analysis, rig hands can size the sand control media according to reservoir requirements. Standard mesh sizes offered with the system are 20, 30, or 40.
Tube components
When the conduit tube extends to the formation face, an area of filter cake is trapped on the face of the tube. One of the main components of the tube is a polymer/acid sealant that BOT personnel inject into the sand control media during the manufacturing process, preventing it from becoming plugged with debris. When the polymer degrades at downhole temperatures, the acid releases and dissolves the filter cake from the conduit tube and the formation. The dissolution of the filter cake transforms the tube into a continuous pathway to the virgin producing formation.
The acid does not cause corrosion of metal parts or tubulars. The polymers used to encapsulate the acid are water soluble and known not to incur formation damage.
Conduit tube density as high as 24 tubes per foot (TPF) enable open-hole performance characteristics.
Chemical release
The polymer/acid polymer injection provides a means of acid clean-up for the carbonaceous material found in most drill-in fluids. The release of the acid needs to be delayed until the flow conduit tubes are in place. Since the rate of dissolution is proportional to temperature, several types of polymers are available to ensure that the acid is not released too soon.
In each test, laboratory technicians melted approximately 10 grams of polymer with 20% organic acid and injected it into a cylindrical mold. They then placed this pellet into a pressurized vessel containing a known weight of calcium carbonate slurried in 2% KCl brine. After specified intervals of time, the rig hands opened the vessel and recovered and weighed the remaining calcium carbonate to determine the percent reacted.
BOT can design release times from a range of several hours up to several months using of the appropriate polymer or mixture. As the temperature increases, the flexibility of release times narrows due to the availability of polymers that can encapsulate acids and are also soluble. Even under these constraints, six-hour release times at 300° F (149° C) are obtainable.
Tool system
For installation, BOT personnel installed telescoping conduits in a joint of production liner prior to running in the hole. The company pre-determines tube density (TPF), mesh size for sand control, polymer selection, and interval length based on wellbore characteristics. The tool system runs in the hole similar to a standard liner hanger deployment operation. BOT personnel can rotate the liner/completion system while running in the hole, and circulation is possible for well control. Upon reaching the desired depth, BOT personnel correlate the liner/completion system on depth by convention means and increases the flow rate through the workstring using a flow actuating landing collar (FALC). When the flow rate falls to zero, the FALC closes and hydraulically isolates the completion unit and running tools for activation. Packer cups on the running tool isolate hydraulic pressure applied to the system at the liner hanger.
The next step is to hydraulically set the liner hanger and release it from the setting tools. As BOT personnel apply hydraulic pressure to the entire liner, a mechanical force in the upward direction occurs but hydraulic hold-down buttons on the running tool negate it. The buttons keep the running tools and workstring from being pumped up the hole. After BOT personnel release the running tools from the liner, an increase in pressure then will hydraulically extend the flow conduit tubes. The drill-in fluid that is in the drilled hole forms a filter cake on the ID of the completion system that will hold any applied pressure to the workstring. BOT personnel apply pressure to the workstring then extend the conduit tubes out to the formation. At a predetermined applied pressure, an expendable seat shears out in the bottom of the FALC to re-establish circulation out the bottom of the liner. Since the extension pressure of the conduit tubes is lower than the shear out pressure of the expendable seat, one can assume that the conduit tubes have fully extended as designed. Once BOT personnel re-establish circulation, they lower the running tool to bottom through the liner and the completion system. The running tool has a gauge ring that is slightly under the drift of the product liner that the BOT personnel run through the completion system. The gauge ring mechanically extends any conduit tubes that were not hydraulically extended. Running the gauge ring through the production liner ensures a full opening ID. Once the gauge ring runs through the conduit tubes, the running tools continue to the bottom of the production liner. At the bottom of the running tool are a set of seals that sting into a receptacle in the top of the FALC. Once BOT personnel sting these seals into the FALC, primary cementing operations may begin. After they pump cement and land the final dart in the FALC, a pressure increase activates the liner top packer setting dogs. The BOT personnel pick up the seals out of the FALC, and reverse out any excess cement in the workstring. They then raise the running tools to the top of the liner. Once the running tools are out of the liner top, the liner top packer setting dogs fully expand, and simple set-down weight on the liner top sets the packer. When BOT personnel pull the tools from the well, sand-free production can begin.
Cost analysis
The JIP design criteria called for system cost to be equal to or less than that of a conventional gravel pack, liner hanger, and tubing conveyed perforating job. In a line-item-by-line item comparison, the tool cost of the system developed is about equal to the tool cost of a conventional gravel pack job with a liner hanger and tubing conveyed perforating job. The two major areas of cost reduction for the operator are service personnel and overall rig time. Since the one-trip sand control completion system includes running a liner hanger, installing sand control, and perforating in the same trip, it requires only one service representative (and a back-up) on the rig floor. A conventional gravel pack, liner hanger, and tubing conveyed perforating job would require up to six service company personnel. Since running the one-trip system takes about a third of the time required to run a conventional gravel pack, liner hanger, and perforating job, the total cost savings in regards to service personnel is 93%. Regarding rig time, since the one-trip system requires one-third the time required for conventional completions, rig timesavings equate to 72%.
Another area of savings is the cost of non-conformance associated with risk involved with running perforating charges. Since no frac pack or gravel pack operations are required, there is no need for large pumps and crews to be on and off rigs. This reduces risk both operationally and environmentally while simplifying logistics and equipment movement.
Editor’s Note: This is a summary of SPE/IADC 92596 presented at the February 2005 Drilling Conference in Amsterdam, The Netherlands.